Treatment fluids comprising weakly emulsifying surfactants and associated methods

ABSTRACT

Provided are acidic treatment fluids comprising a weakly emulsifying surfactant, an aqueous base fluid, and an acid. In some embodiments, the treatment fluids are capable of forming short-lived oil-in-acid emulsions due, at least in part, to the interaction of at least a portion of the weakly emulsifying surfactant with one or more oil or gas molecules within a subterranean formation.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a Continuation Application of U.S. NationalStage application Ser. No. 14/778,236, filed 18 Sep. 2015 which is basedon International Patent Application No. PCT/US2014/033806, filed 11 Apr.2014 which claims the benefit of the filing of U.S. Provisional PatentApplication Ser. No. 61/814,089, entitled “Treatment Fluids ComprisingWeakly Emulsifying Surfactants and Associated Methods,” filed on 19 Apr.2013, all of which are incorporated herein by reference in theirentirety for all purposes.

BACKGROUND

The present invention relates to methods and compositions for treatingsubterranean formations. More particularly, the present inventionrelates to treatment fluids that comprise a weakly emulsifying (“WE”)surfactant, and associated methods.

Treatment fluids may be used in a variety of subterranean treatments.Such treatments include, but are not limited to, stimulation treatmentsand enhanced or improved oil recovery operations. As used herein, theterm “treatment,” or “treating,” refers to any subterranean operationthat uses a fluid in conjunction with a desired function and/or for adesired purpose. The term “treatment,” or “treating,” does notnecessarily imply any particular action by the fluid.

One common production stimulation operation that employs a treatmentfluid is hydraulic fracturing. Hydraulic fracturing operations generallyinvolve pumping a treatment fluid (e.g., a fracturing fluid) into a wellbore that penetrates a subterranean formation at a sufficient hydraulicpressure to create or enhance one or more cracks, or “fractures,” in thesubterranean formation. The fracturing fluid may comprise particulates,often referred to as “proppant particulates,” that are deposited in thefractures. The proppant particulates function, inter alia, to preventthe fractures from fully closing upon the release of hydraulic pressure,forming conductive channels through which fluids may flow to the wellbore. Once at least one fracture is created and the proppantparticulates are substantially in place, the viscosity of the fracturingfluid usually is reduced, and the fracturing fluid may be recovered fromthe formation.

Another production stimulation operation that employs a treatment fluidis an acidizing treatment. In acidizing treatments, subterraneanformations comprising acid-soluble components, such as those present incarbonate and sandstone formations, are contacted with a treatment fluidcomprising an acid. For example, where hydrochloric acid contacts andreacts with calcium carbonate in a formation, the calcium carbonate isconsumed to produce water, carbon dioxide, and calcium chloride. Afteracidization is completed, the water and salts dissolved therein may berecovered by producing them to the surface, e.g., “flowing back” thewell, leaving one or more voids (e.g., wormholes) within the formation,which enhance the formation's permeability and may increase the rate atwhich hydrocarbons may subsequently be produced from the formation. Onemethod of acidizing, known as “fracture acidizing,” comprises injectinga treatment fluid comprising an acid into the formation at a pressuresufficient to create or enhance one or more fractures within thesubterranean formation. The acid treatment fluid may leave one or morevoids within the formation in addition to the one or more fracturesenhanced within the formation. Another method of acidizing, known as“matrix acidizing,” comprises injecting the treatment fluid into theformation at a pressure below that which would create or enhance one ormore fractures within the subterranean formation. This acidizing methodmay likewise leave one or more voids within the formation.

Surfactants are widely used in stimulation operations, includinghydraulic fracturing and acidizing (both fracture acidizing and matrixacidizing) treatments. Surfactants may also be used in enhanced orimproved oil recovery operations. Many variables may affect theselection of a surfactant for use in such treatments and operations,such as interfacial surface tension, wettability, compatibility withother additives (such as other additives used in acidizing treatments),and emulsification tendency. Many conventional treatments and operationssuch as hydraulic fracturing and acidizing treatments utilizenon-emulsifying (“NE”) surfactants in order to avoid the formation oftight emulsions between the oil and aqueous phases within a formation.Tight emulsions are thought to block the oil and gas flow by pluggingthe pore throats, voids, fractures, or other channels in the formation.This formation damage could drastically reduce production from theformation.

However, the use of NE surfactants in stimulation operations such asacidizing treatments may result in sub-optimal oil and/or gas flow fromthe formation.

BRIEF DESCRIPTION OF THE FIGURES

A more complete understanding of the present disclosure and advantagesthereof may be acquired by referring to the following description takenin conjunction with the accompanying drawings, wherein:

FIG. 1 is a graph illustrating a comparison of separation rates of oiland aqueous phases for both NE surfactant-containing and WEsurfactant-containing acidic treatment fluids 10 minutes after mixing,as measured by an emulsion dispersion analyzer.

FIG. 2 is a photograph of sample mixtures of oil and aqueous fluidsubjected to a sludge tendency test conducted at reservoir temperatureand live acid conditions.

FIG. 3 is a photograph of sample mixtures of oil and aqueous fluidsubjected to a sludge tendency test conducted at reservoir temperatureand spent acid conditions.

FIG. 4 is a graph illustrating comparison of production between wellstreated with treatment fluids including a WE surfactant, and nearbyoffset wells treated with treatment fluids including a NE surfactant.

While the present invention is susceptible to various modifications andalternative forms, specific exemplary embodiments thereof have beenshown by way of example in the drawings and are herein described indetail. It should be understood, however, that the description herein ofspecific embodiments is not intended to limit or define the invention tothe particular forms disclosed, but on the contrary, the intention is tocover all modifications, equivalents, and alternatives falling withinthe spirit and scope of the invention as defined by the appended claims.The figures should in no way be used to limit the meaning of the claimterms.

The features and advantages of the present invention will be readilyapparent to those skilled in the art upon a reading of the descriptionof the preferred embodiments that follows.

DESCRIPTION OF PREFERRED EMBODIMENTS

The present disclosure relates to methods and compositions for treatingsubterranean formations. More particularly, the present disclosurerelates to treatment fluids that comprise a WE surfactant, andassociated methods.

The treatment fluids of the present disclosure generally comprise a WEsurfactant and an aqueous base fluid. The treatment fluids of someembodiments may further comprise an acid. Additionally, other additivessuitable for use in the particular application may be included in thetreatment fluids of the present disclosure as recognized by one ofordinary skill in the art having the benefit of this disclosure.

Among the many potential advantages and benefits of the methods andfluids of the present disclosure, the WE surfactant of treatment fluidsof some embodiments of the present disclosure may aid in the formationof one or more short-lived oil-in-acid or oil-in-water emulsions, whichmay enhance mobility of oil and/or gas in a subterranean formation whilepreventing or otherwise avoiding the formation of tight emulsionsbetween the oil and aqueous phases within the formation. Specifically,the one or more oil-in-acid or oil-in-water emulsions formed bytreatment fluids of some embodiments may lower the interfacial surfacetension between oil and aqueous phases, thereby enhancing the tendencyfor oil and/or gas molecules to migrate from the interior of theformation to the wellbore. In addition, these short-lived oil-in-acid oroil-in-water emulsions may be capable of dispersing additional oiland/or gas droplets into the acid or water phase and enabling those oiland/or gas molecules to deform and squeeze through tiny pore spaces inthe formation rocks. In some embodiments, the WE surfactant of thetreatment fluid is capable of adsorbing on either or both of a rocksurface of the subterranean formation and one or more oil and/or gasmolecules within the subterranean formation, so as to increase theprobability of stripping oil and/or gas from rocks within thesubterranean formation. In some embodiments, short-lived oil-in-acid oroil-in-water emulsions may additionally or instead temporarily delayacid spending, thereby potentially leading to the creation of largervoids, or wormholes, in the rock of the formation.

The WE surfactants of certain treatment fluids of the present disclosuremay be capable of preventing and/or dispersing acid-induced sludge.Acid-induced sludge may cause significant well damage during acidizingtreatments by, for example, plugging pore spaces in the subterraneanformation, thereby preventing or substantially hindering the flow of oiland/or gas through the formation to the wellbore. It is believed thatacid-induced sludge may form during acid stimulation because of theinteraction between strong acid in acidic treatment fluids (e.g., 15%HCl acid) and asphaltene or paraffin compounds in the oil and/or gas.See Reitjens, M. and Nieuwpoort, M. 1999. Acid-Sludge: How SmallParticles Can Make a Big Impact. Paper SPE 54727 presented at the SPEEuropean Formation Damage Conference, The Hague, The Netherlands, 31May-1 June. http://dx.doi.org/10.2118/54727-MS (also availablehttp://www.onepetro.org/mslib/servlet/onepetropreview?id=00054727&soc=SPE).The sludge could become large enough to plug off pore spaces in theformation, causing formation damage. In some embodiments, WE surfactantsmay be capable of diffusing to the interface between oil and aqueousphases in order to counteract or otherwise prevent the effect ofasphaltene or paraffin compounds on the interface, thereby preventingthem from coming out of the oil phase. This may, in some embodiments,permit the use of acidic treatment fluids without the need foradditional anti-sludge agents. Similarly, the presence of a WEsurfactant in certain treatment fluids of the present disclosure mayeliminate the need to additionally include penetrating surfactants inthe treatment fluid of those embodiments.

Accordingly, treatment fluids of some embodiments of the presentdisclosure may provide significant advantages in oil and/or gasproduction over the use of treatment fluids that instead comprise NEsurfactants. NE surfactants, in contrast to the WE surfactants of someembodiments of the present disclosure, are typically used to inhibit anydegree of formation of emulsions, including oil-in-acid, oil-in-water,or other oil-in-aqueous phase emulsions. For example, FIG. 1 shows acomparison of emulsion tendency between NE surfactant-containingtreatment fluids and WE surfactant-containing treatment fluids.Specifically, FIG. 1 shows oil in acid separation rates as determinedusing an emulsion dispersion analyzer at 10 minutes after mixing with atreatment fluid containing either a NE surfactant or a WE surfactant(and which was otherwise substantially identical) at 4,000 ppm (0.4%)surfactant loading. As shown in FIG. 1, the treatment fluid containingWE surfactant has a lower separation rate on the index (scale of 0-1) asquantified by the emulsion dispersion analyzer, as compared to theseparation rate for the treatment fluid containing the NE surfactant.The lower separation rate of the WE-containing fluids may indicate,among other things, that the WE surfactant has a greater emulsiontendency than does the NE surfactant.

WE surfactants suitable for use in some embodiments of the presentdisclosure include any surfactant capable of forming relativelyshort-lived, or transient, oil-in-acid, oil-in-water, or otheroil-in-aqueous phase emulsions. In some embodiments, suitable WEsurfactants may be characterized by their capability to form oil-in-acidor oil-in-water emulsions that break and reform whenever the emulsion issubjected to shear forces. Thus, in some embodiments, use of a treatmentfluid including the WE surfactant in a formation may result in emulsionsthat break apart and reform when subjected to shear flow in theformation.

In some embodiments, whether a surfactant will function as a WEsurfactant may depend upon one or more characteristics of the crude oiland/or gas of the formation (such as any one or more of thecharacteristics of crude oil and/or gas in a formation discussedherein). Thus, in some embodiments, crude oil analysis may be requiredto determine a suitable WE surfactant for use in a formation comprisingthe analyzed crude oil. Further, in some embodiments, a surfactant'ssuitability to function as a weakly emulsifying surfactant may beconfirmed by appropriate testing, such as dynamic surface tension,interfacial surface tension, wettability, emulsification tendency and/orsludge tendency tests, which are known in the art. See, e.g., Xu, L. andFu, Q. 2012. Ensuring Better Well Stimulation in Unconventional Oil andGas Formations by Optimizing Surfactant Additives. Paper SPE 154242prepared for presentation at the SPE Western Regional Meeting held inBakersfield, Calif., USA 19-23 Mar. 2012; Grattoni, C. A., Chiotis, E.D., and Dawe, R. A. 1995. Determination of Relative Wettability ofPorous Sandstones by Imbibition Studies. Journal of Chem. Tech. andBiotech., 64 (1): 17-24. doi: 10.1002/jctb.280640104; Hirasaki, G.,Zhang, D. L. 2004. Surface Chemistry of Oil Recovery From Fractured,Oil-Wet, Carbonate Formations. SPE Journal, 9 (2): 15-162. doi:10.2118/88365-PA; Somasundaran, P. and Zhang, L. 2006. Adsorption ofSurfactants on Minerals for Wettability Control in Improved Oil RecoveryProcesses. Journal of Petroleum Science and Engineering, 52 (1-4):198-212. doi:10.1016/j.petro1.2006.03.022; Tadros, T. F. 2005. AppliedSurfactants: Principles and Applications, Wiley-VCH; Tongcumpou, C.,Acosta, E. J., Quencer, L. B., Joseph, A. F., Scamehorn, J. F.,Sabatini, D. A., Yanumet, N. and Chavadej, S. 2005. MicroemulsionFormation and Detergency with Oily Soils: III. Performance andMechanisms. Journal of Surfactants and Detergents, 8 (2):147-156. doi:10.1007/s11743-005-340-8. One of ordinary skill in the art with thebenefit of this disclosure will recognize how to determine whether asurfactant is suitably weakly emulsifying for a particular crude oil.

The WE surfactant may in some embodiments be cationic, while in otherembodiments it may be anionic, or in yet other embodiments, amphoteric,zwitterionic, or non-ionic, respectively. In some embodiments, thedesired ionization, if any, of the WE surfactant may be determined basedat least in part upon one or more characteristics of the oil and/or gasof a subterranean formation. For example, the charge of a WE surfactantof some embodiments of the treatment fluid may be such that the WEsurfactant is capable of inducing pair interactions (such as, e.g.,electrostatic interactions) with one or more molecules of oil and/or gasin the subterranean formation. The mechanism of paired interaction hasbeen discussed by Salehi et al., where they demonstrate the two mainmechanisms responsible for the wettability alteration for oil wet andmixed wet formation rocks are ion-pair formation and adsorption ofsurfactant molecules through interactions with the adsorbed crude oilcomponents on the rock surface. See Salehi, M., Johnson, S. J., andLiang, J. T. 2008. Mechanistic Study of Wettability Alteration usingSurfactants with Applications in Naturally Fractures Reservoirs.Langmuir 24 (24): 14099-107, http://dx/doi/org/10.1021/1a802464u (alsoavailable http://pubs.acs.org/doi/abs/10.1021/1a802464u). For example,by using an anionic surfactant that pairs with cationic oil molecules bymeans of electrostatic interactions, the probability of stripping oilfrom rocks increases.

Thus, where the oil and/or gas of a subterranean formation containspredominantly alkaline compounds, which are typically positively chargedin nature, the WE surfactant of some embodiments of the presentdisclosure may be anionic so as to be capable of inducing electrostaticpair interactions with positively-charged oil and/or gas molecules. Inother instances, the oil and/or gas of a subterranean formation maycontain a mixture of alkaline and acidic compounds. In such acircumstance, it may be advantageous to use an amphoteric and/orzwitterionic WE surfactant according to some embodiments of the presentdisclosure.

Furthermore, the amphoteric and/or zwitterionic WE surfactants of someembodiments may exhibit different charge and/or reactivity at differentranges of pH. For instance, some WE surfactants that are amphotericand/or zwitterionic at pH less than about 2 may become anionic,cationic, or non-ionic at pH greater than about 2. Because the downholepH may change during acidization (for example, pH may rise from in therange of 0-1, to about 4, as the acid is spent), the characteristics ofWE surfactants of some embodiments may change during the process of anacidization treatment.

Other characteristics of oil and/or gas within the formation that mightaffect the determination of desired WE surfactant charge include, butare not limited to: weight percentages of saturates, aromatics, resinsand asphaltenes.

Suitable non-ionic WE surfactants of some embodiments may include, butare not limited to: ethoxylated alcohols and polyglucosides. In someembodiments, non-ionic WE surfactants may include ethoxylated long-chainalcohols (e.g., ethoxylated dodecanol). Ethoxylation may take place atany point along the alcohol. Suitable cationic WE surfactants of someembodiments may include, but are not limited to: alkyl ammoniumbromides. In some embodiments, the alkyl chain of the alkyl ammoniumbromide may be anywhere from 1 to 50 carbons long, and be branched orun-branched. Thus, an example embodiment may include an alkyl ammoniumbromide that comprises a 16-carbon chain alkyl component (e.g., cetyltrimethyl ammonium bromide). Suitable anionic WE surfactants of someembodiments may include, but are not limited to: alkyl sulfonates (e.g.,methyl sulfonate, heptyl sulfonate, decylbenzene sulfonate,dodecylbenzene sulfonate, etc.) and alkoxylated sulfates. Suitableamphoteric and/or zwitterionic WE surfactants of some embodiments mayinclude, but are not limited to, hydroxysultaines (e.g., cocoamidopropylhydroxysultaine, lauramidopropyl hydroxysultaine, laurylhydroxysultaine, etc.).

In some embodiments, the WE surfactant may be present in a treatmentfluid in an amount sufficient to form one or more relatively short-livedoil-in-acid or oil-in-water emulsions within a subterranean formation.For example, in some embodiments, the WE surfactant may be present inthe treatment fluid in an amount of from about 0.1 to 50 gallons ofsurfactant per thousand gallons of acid, water, and/or other aqueousbase fluid (“gpt”), or put another way, approximately 100 to 50,000 ppm.In other example embodiments, the WE surfactant may be present in thetreatment fluid in an amount of from about 2 to 40 gpt (approximately2,000 ppm to 40,000 ppm), or in other embodiments, from about 3 to 25gpt (approximately 3,000 ppm to about 25,000 ppm). In some embodiments,the WE surfactant may be present in the treatment fluid in an amount offrom about 4 gpt to about 18 gpt (approximately 4,000 ppm to 18,000ppm). In some embodiments, WE surfactant may be added to a treatmentfluid in place of one or more other components that would otherwiseconventionally be present (e.g., penetrating surfactants or anti-sludgeagents). In such embodiments, an amount of WE surfactant on the higherend of the above ranges may be desired.

The aqueous base fluid used in some embodiments of the treatment fluidsof the present disclosure may comprise fresh water, saltwater (e.g.,water containing one or more salts dissolved therein), brine (e.g.,saturated saltwater), seawater, or any combination thereof. Generally,the water may be from any source, provided that it does not containcomponents that might adversely affect the stability of the treatmentfluids of the present disclosure. One of ordinary skill in the art, withthe benefit of this disclosure, will recognize what components mightadversely affect the stability and/or performance of the treatmentfluids of the present disclosure.

The acid optionally used in some embodiments of the treatment fluids ofthe present disclosure may comprise any acid suitable for use inacidizing treatments, such as matrix acidizing or fracture acidizing.Examples of suitable acids for use in various embodiments include, butare not limited to: hydrochloric acid, hydrofluoric acid, formic acid,acetic acid, citric acid, glycolic acid, hydroxyacetic acid, lacticacid, hydrofluoric acid, 3-hydroxypropionic acid, carbonic acid, andethylenediaminetetraacetic acid. An example of a suitable commerciallyavailable acid is “VOLCANIC ACID II™” available from Halliburton EnergyServices, Inc. Alternatively or in combination with one or more acids,the treatment fluids of the present disclosure may comprise a salt of anacid. A “salt” of an acid, as that term is used herein, refers to anycompound that shares the same base formula as the referenced acid, butone of the hydrogen cations thereon is replaced by a different cation(e.g., an antimony, bismuth, potassium, sodium, calcium, magnesium,cesium, or zinc cation). Examples of suitable salts of acids include,but are not limited to, sodium acetate, sodium formate, sodium citrate,sodium hydroxyacetate, sodium lactate, sodium fluoride, sodiumpropionate, sodium carbonate, calcium acetate, calcium formate, calciumcitrate, calcium hydroxyacetate, calcium lactate, calcium fluoride,calcium propionate, calcium carbonate, cesium acetate, cesium formate,cesium citrate, cesium hydroxyacetate, cesium lactate, cesium fluoride,cesium propionate, cesium carbonate, potassium acetate, potassiumformate, potassium citrate, potassium hydroxyacetate, potassium lactate,potassium fluoride, potassium propionate, potassium carbonate, magnesiumacetate, magnesium formate, magnesium citrate, magnesium hydroxyacetate,magnesium lactate, magnesium fluoride, magnesium propionate, magnesiumcarbonate, zinc acetate, zinc formate, zinc citrate, zinchydroxyacetate, zinc lactate, zinc fluoride, zinc propionate, zinccarbonate, antimony acetate, antimony formate, antimony citrate,antimony hydroxyacetate, antimony lactate, antimony fluoride, antimonypropionate, antimony carbonate, bismuth acetate, and bismuth formate,bismuth citrate, bismuth hydroxyacetate, bismuth lactate, bismuthfluoride, bismuth carbonate, and bismuth propionate. The treatmentfluids of some embodiments of the present disclosure may include anycombination of two or more acids and/or salts thereof.

The optional acid (and/or salts thereof) may be present in the treatmentfluid of some embodiments of the present disclosure in an amountsufficient to make the treatment fluid acidic. In some embodiments, thepH may be less than about 7. In other embodiments, the pH of thetreatment fluid may be less than about 6, or in other embodiments, lessthan about 5. In some embodiments, the treatment fluid may be stronglyacidic (e.g., having a pH less than about 3, or in other embodiments,less than about 2). In some embodiments, pH may be approximately 0. So,for example, in some embodiments the acid (and/or salts thereof) may bepresent in the range of from about 1% by weight of the treatment fluidto about 30% by weight of the treatment fluid. In certain embodiments,the acid (and/or salts thereof) may be present in the treatment fluid inthe range of from about 5% by weight of the treatment fluid to about 20%by weight of the treatment fluid. In other embodiments, the treatmentfluid may be 100% acid (prior to addition of WE surfactant and any otheradditives discussed herein).

The treatment fluids of some embodiments may include solvents, such asxylene, toluene, aromatics, or butyl glycol. Thus, for example, atreatment fluid of some embodiments may include ethylene glycolmono-butyl ether.

The treatment fluids of some embodiments may include particulates (suchas proppant particulates or gravel particulates) suitable for use insubterranean applications. Particulates suitable for use in the presentdisclosure may comprise any material suitable for use in subterraneanoperations. Suitable particulate materials include, but are not limitedto, sand, bauxite, ceramic materials, glass materials, polymermaterials, Teflon® materials, nut shell pieces, cured resinousparticulates comprising nut shell pieces, seed shell pieces, curedresinous particulates comprising seed shell pieces, fruit pit pieces,cured resinous particulates comprising fruit pit pieces, wood, compositeparticulates, and any combination thereof. Suitable compositeparticulates may comprise a binder and a filler material whereinsuitable filler materials include silica, alumina, fumed carbon, carbonblack, graphite, mica, titanium dioxide, meta-silicate, calciumsilicate, kaolin, talc, zirconia, boron, fly ash, hollow glassmicrospheres, solid glass, and any combination thereof. The particulatesize generally may range from about 2 mesh to about 400 mesh on the U.S.Sieve Series; however, in certain circumstances, other sizes may bedesired and will be entirely suitable for practice of the presentdisclosures. In particular embodiments, preferred particulates sizedistribution ranges are one or more of 6/12, 8/16, 12/20, 16/30, 20/40,30/50, 40/60, 40/70, or 50/70 mesh. It should be understood that theterm “particulate,” as used in this disclosure, includes all knownshapes of materials, including substantially spherical materials,fibrous materials, polygonal materials (such as cubic materials), andmixtures thereof. Moreover, fibrous materials, that may or may not beused to bear the pressure of a closed fracture, are often included infracturing and sand control treatments. In certain embodiments, theparticulates included in the treatment fluids of some embodiments of thepresent disclosure may be coated with any suitable resin or tackifyingagent known to those of ordinary skill in the art.

The treatment fluids of some embodiments may additionally or insteadinclude one or more of a variety of well-known additives, such as gelstabilizers, salts, fluid loss control additives, scale inhibitors,organic corrosion inhibitors, catalysts, clay stabilizers, biocides,bactericides, friction reducers, gases, foaming agents, iron controlagents, solubilizers, pH adjusting agents (e.g., buffers), and the like.In certain embodiments, the treatment fluids may include salts (e.g.MgCl₂) that may, inter alia, prevent the precipitation of calcium whensuch treatment fluids are used to acidize formations containing calciumcarbonate. Those of ordinary skill in the art, with the benefit of thisdisclosure, will be able to determine the appropriate additives for aparticular application.

The treatment fluids of the present disclosure may be prepared by anysuitable method. In some embodiments, the treatment fluids may beprepared on the job site. As an example of such an on-site method, a WEsurfactant may be added to a treatment fluid (e.g., a hydraulicfracturing fluid, a fracture acidizing fluid, or a matrix acidizingfluid) during pumping.

Furthermore, additional additives, as discussed above, may be combinedwith the treatment fluid and/or the aqueous base fluid as desired. Forexample, a particulate additive (e.g., a particulate scale inhibitor) orparticulates (e.g., gravel particulates or proppant particulates) may besuspended in the treatment fluid. In some embodiments, to facilitatemixing with the aqueous base fluid and the acid, the WE surfactant maybe combined with a surfactant solubilizer prior to its combination withthe other components of the treatment fluid. The surfactant solubilizermay be any suitable surfactant solubilizer, such as water, simplealcohols, and any combination thereof. For example, in some embodiments,the WE surfactant may be provided in a mixture that comprises thesurfactant solubilizer and the WE surfactant. One of ordinary skill inthe art, with the benefit of this disclosure, will be able to determineother suitable methods for preparation of the treatment fluids.

The present disclosure in some embodiments provides methods for usingthe treatment fluids to carry out a variety of subterranean treatments,including but not limited to, hydraulic fracturing treatments andacidizing treatments. In some embodiments, the treatment fluids of thepresent disclosure may be used in treating a portion of a subterraneanformation, for example, in acidizing treatments such as matrix acidizingor fracture acidizing. In certain embodiments, a treatment fluid thatcomprises a WE surfactant and an aqueous base fluid may be introducedinto a subterranean formation. In some embodiments, the treatment fluidmay be introduced into a well bore that penetrates a subterraneanformation. In some embodiments, the treatment fluid may be introduced ata pressure sufficient to create or enhance one or more fractures withinthe subterranean formation (e.g., hydraulic fracturing).

In some embodiments, the treatment fluid further comprising an acid maybe introduced at a pressure sufficient to cause at least a portion ofthe treatment fluid to penetrate at least a portion of the subterraneanformation, and the treatment fluid may be allowed to interact with thesubterranean formation so as to create one or more voids in thesubterranean formation (for example, in acidizing treatments).Introduction of the treatment fluid may in some of these embodiments becarried out at or above a pressure sufficient to create or enhance oneor more fractures within the subterranean formation (e.g., fractureacidizing). In other embodiments, introduction of the treatment fluidmay be carried out at a pressure below that which would create orenhance one or more fractures within the subterranean formation (e.g.,matrix acidizing).

In some instances, the treatment fluid may facilitate the formation ofrelatively short-lived oil-in-acid and/or oil-in-water emulsions due, atleast in part, to the interaction of at least a portion of the WEsurfactant with at least a portion of oil and/or gas molecules withinthe formation. In some embodiments, at least a portion of the WEsurfactant may diffuse to an interface between oil and aqueous phaseswithin the subterranean formation in order to counteract or otherwiseprevent the formation of acid-induced sludge. In some embodiments, theWE surfactant of the treatment fluid may instead or in additionfacilitate one or more pair interactions (such as electrostaticinteractions) between at least a portion of the treatment fluid and atleast a portion of oil and/or gas molecules in the formation.Furthermore, the treatment fluid of some embodiments may delay acidspending due at least in part to the presence of the WE surfactant.

The methods of some embodiments may also or instead include introducinginto a subterranean formation a treatment fluid that comprises a WEsurfactant, an aqueous base fluid, and an acid, in the absence of anyadditional anti-sludge agents; and allowing at least a portion of thetreatment fluid to interact with at least a portion of the oil and/orgas of the subterranean formation so as to prevent the formation ofacid-induced sludge.

The methods of some embodiments may also or instead include introducinginto a subterranean formation a treatment fluid that comprises a WEsurfactant and an aqueous base fluid, in the absence of any additionalpenetrating surfactants; and allowing the WE surfactant to facilitatethe penetration of at least a portion of the subterranean formation byat least a portion of the treatment fluid.

The methods of some embodiments may also or instead include using thetreatment fluid in enhanced or improved oil recovery operations.

Furthermore, any or all of the treatment fluids used in theaforementioned methods of some embodiments of the present disclosure mayin other embodiments further include any one or more of the previouslydiscussed additional additives (e.g., gel stabilizers, salts, fluid losscontrol additives, scale inhibitors, organic corrosion inhibitors,catalysts, clay stabilizers, biocides, bactericides, friction reducers,gases, foaming agents, iron control agents, solubilizers, pH adjustingagents (e.g., buffers), and the like).

In some embodiments, the present disclosure provides a methodcomprising: providing a treatment fluid that comprises a weaklyemulsifying surfactant, an aqueous base fluid, and an acid; andintroducing the treatment fluid into at least a portion of asubterranean formation.

In other embodiments, the present disclosure provides a methodcomprising: providing a treatment fluid that comprises a weaklyemulsifying surfactant and an aqueous base fluid; and introducing thetreatment fluid into at least a portion of a subterranean formation ator above a pressure sufficient to create or enhance one or morefractures in the subterranean formation.

In other embodiments, the present disclosure provides a treatment fluidcomprising: a weakly emulsifying surfactant, an aqueous base fluid, anacid, and a weakly-emulsifying surfactant selected from the groupconsisting of: ethoxylated long-chain alcohols, polyglucosides, alkylammonium bromides; alkyl sulfonates; alkoxylated sulfates;hydroxysultaines; and any combination thereof.

To facilitate a better understanding of the present invention, thefollowing examples of preferred embodiments are given. In no way shouldthe following examples be read to limit, or define, the scope of theinvention.

EXAMPLES Example 1

Oil Composition Analysis. Four crude oil samples were taken from fourseparate wells in the Monterrey Formation in California, numbered 1, 2,3, and 4. Oil composition analysis was performed by following standardtitration for determining acid and base numbers. Table 1 shows theresults of oil composition analysis for four crude oils. In Table 1, APIGravity shows the American Petroleum Institute Gravity (a measure ofdensity of a petroleum liquid relative to water, where 10 is equal towater's density); % Mass shows the amount of paraffin and asphaltene inthe oil on a % mass basis; Acid No. is a measure of acidity based uponthe amount of KOH (in mg) needed to neutralize the acids per gram ofoil; and Base No. is the amount of KOH (in mg) per gram of oil.

TABLE 1 OIL COMPOSITION ANALYSIS FOR FOUR CRUDE OILS API % Mass % MassAcid No., Base No, Well ID Gravity Paraffin Asphaltene mg KOH/g mg KOH/gNo. 1 49.5 3.10 0.50 0.19 1.61 No. 2 46.6 1.90 0.80 0.10 1.04 No. 3 21.38.50 3.10 1.09 3.40 No. 4 25.4 2.10 4.60 0.96 9.54

The compositions of crude oils can vary significantly in terms of totalacid and base numbers, even in the same formation. The oil analysissuggests that the oils from the four sample wells contain predominantlyalkaline compounds, which are typically positively charged in nature.Thus, it was determined that a negatively charged WE surfactant could beused to induce extensive pair interactions with oil molecules.

Sludge and Emulsion Tendency Tests. Sludge and emulsion tendency testswere conducted on oils from Well No. 1 and Well No. 3, respectively, bymixing equal volumes of crude oils and 15% HCl acid for at least 30 minat reservoir temperature. A total of 4,000 ppm of the same non-ionic NEsurfactant was added to the acid phase, and the acid phase was thenmixed with each of the Well No. 1 and the Well No. 3 crude oil samples.Likewise, a total of 4,000 ppm of the same WE surfactant (here, laurylhydroxysultaine) was added to the acid phase, and the acid phase wasthen mixed with each of the Well No. 1 and the Well No. 3 crude oilsamples. Spent acid was prepared by adding MgCl₂ and CaCl₂ to 15% HClacid, in which the pH was raised to 4.0.

A sludge tendency test was conducted at reservoir temperature andlive/spent acid conditions in order to observe how well the oil phaseseparates from the water phase after mixing. Ideally, the interfaceshould be clear of emulsion pads and no sludge should be present ineither the acid or water phase. FIGS. 2 and 3 present sludge tendenciesfor the blank, NE, and WE surfactant at both live (FIG. 2) and spent(FIG. 3) acid conditions, based upon crude oil taken from Wells 1 and 3.In particular, FIG. 2 shows control fluids (i.e.,non-surfactant-containing, or blank, fluids) 101 and 301 from Wells 1and 3, respectively; it also shows oil samples with NE surfactant (102and 302) from Wells 1 and 3, respectively, and samples with WEsurfactant (103 and 303) from Wells 1 and 3, respectively. Likewise,FIG. 3 shows control fluids 111 and 311 from Wells 1 and 3;NE-surfactant-containing samples 122 and 322 from Wells 1 and 3; andWE-surfactant-containing samples 133 and 333 from Wells 1 and 3. It isclear that the interfaces in each oil and acid mixture appear to be freeof sludge. For the WE surfactant in both the live samples 103 and 303and spent samples 133 and 333, the acid phase appears darker, which is atypical result of oil molecules being dispersed and generating oil inacid emulsions.

Emulsion tendency was monitored by placing the samples from Well No. 1and Well No. 3 (both the samples mixed with NE-containing acid and thesamples mixed with WE-containing acid) in an emulsion dispersionanalyzer at ambient temperature, and the oil/acid separation rates weretracked by light scattering. The results are shown in FIG. 1, asdetermined using an emulsion dispersion analyzer at 10 minutes aftermixing with either the NE-containing treatment fluid or theWE-containing treatment fluid, as labeled in FIG. 1. As shown in FIG. 1,the separation index/rate as quantified by the emulsion dispersionanalyzer was far greater for NE surfactant-containing treatment fluids,thereby showing the greater emulsion tendency of treatment fluidsincluding WE surfactant.

Example 2

Four wells in the low permeability Monterrey formation in Californiawere selected and completed with treatment fluids comprising laurylhydroxysultaine, an amphoteric WE surfactant that tends to be come moreanionic at pH above 2, in accordance with various embodiments of thepresent disclosure. The average barrel of oil equivalent (BOE) of thefirst 30 days was compared to eight offset wells, wherein treatmentfluids instead comprising a non-ionic NE surfactant were used. As shownin FIG. 4, BOE from those four wells was higher than in six out of eightoffsets, indicating that the use of WE surfactants in accordance withvarious embodiments of the present disclosure may enable incrementalincreases in production.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered ormodified and all such variations are considered within the scope andspirit of the present invention. In particular, every range of values(of the form, “from about a to about b,” or, equivalently, “fromapproximately a to b,” or, equivalently, “from approximately a-b”)disclosed herein is to be understood as referring to the power set (theset of all subsets) of the respective range of values, and set forthevery range encompassed within the broader range of values. Also, theterms in the claims have their plain, ordinary meaning unless otherwiseexplicitly and clearly defined by the patentee.

What is claimed is:
 1. A method comprising: providing a treatment fluidthat comprises a weakly emulsifying surfactant and an aqueous basefluid; and introducing the treatment fluid into at least a portion of asubterranean formation at or above a pressure sufficient to create orenhance one or more fractures in the subterranean formation; and formingone or more short-lived oil-in-water emulsions within the subterraneanformation.
 2. The method of claim 1 wherein the weakly-emulsifyingsurfactant comprises a compound selected from the group consisting of:ethoxylated long-chain alcohols, polyglucosides, alkyl ammoniumbromides; alkyl sulfonates; alkoxylated sulfates; hydroxysultaines; andany combination thereof.
 3. The method of claim 1, wherein theweakly-emulsifying surfactant comprises an alkyl ammonium bromidecomprising an alkyl chain having between 1 and 50 carbon atoms.
 4. Themethod of claim 1, wherein the weakly-emulsifying surfactant comprisesan alkyl sulfonate selected from the group consisting of methylsulfonate, heptyl sulfonate, decylbenzene sulfonate, dodecylbenzenesulfonate, and any combination thereof.
 5. The method of claim 1,wherein the weakly-emulsifying surfactant comprises a hydroxysultaineselected from the group consisting of: cocoamidopropyl hydroxysultaine,lauramidopropyl hydroxysultaine, lauryl hydroxysultaine, and anycombination thereof.
 6. The method of claim 1, further comprising:allowing at least a portion of the weakly emulsifying surfactant tointeract with at least a portion of the oil, gas, or both of thesubterranean formation so as to prevent the formation of acid-inducedsludge; wherein the treatment fluid contains substantially noanti-sludge agent in addition to the weakly emulsifying surfactant. 7.The method of claim 1, further comprising: wherein the treatment fluidcontains substantially no penetrating surfactant in addition to theweakly emulsifying surfactant.